The present invention is directed generally at controlling well head blow outs, and specifically to a rotating pressure control head having a rapid engagement mechanism and a replaceable and predictably deformable sealing element.
When the hydrostatic weight of the column of mud in a well bore is less than the formation pressure, the potential for a blowout exists. A blowout occurs when the formation expels hydrocarbons into the well bore. The expulsion of hydrocarbons into the well bore dramatically increases the pressure within a section of the well bore. The increase in pressure sends a pressure wave up the well bore to the surface. The pressure wave can damage the equipment that maintains the pressure within the well bore. In addition to the pressure wave, the hydrocarbons travel up the well bore because the hydrocarbons are less dense than the mud. If the hydrocarbons reach the surface and exit the well bore through the damaged surface equipment, there is a high probability that the hydrocarbons will be ignited by the drilling or production equipment operating at the surface. The ignition of the hydrocarbons produces an explosion and/or fire that is dangerous for the drilling operators. In order to minimize the risk of blowouts, drilling rigs are required to employ a plurality of different blowout preventers (BOPs), such as a rotating BOP, an annular BOP, a pipe ram, and a blind ram. Persons of ordinary skill in the art are aware of other types of BOPs. The various BOPs are positioned on top of one another, along with any other necessary surface connections such as nitrogen injection. The stack of BOPs and surface connections is called the BOP stack. A typical BOP stack is illustrated in FIG. 1.
One of the devices in the BOP stack is a rotating BOP. The rotating BOP is located at the top of the BOP stack and is part of the pressure boundary between the well bore pressure and atmospheric pressure. The rotating BOP creates the pressure boundary by employing a ring-shaped rubber or urethane sealing element that squeezes against the drill pipe, tubing, casing, or other cylindrical members (hereinafter, drill pipe). The sealing element allows the drill pipe to be inserted into and removed from the well bore while maintaining the pressure differential between the well bore pressure and atmospheric pressure. The sealing element may be shaped such that the sealing element uses the well bore pressure to squeeze the drill pipe or other cylindrical member. However, most rotating BOPs utilize some type of mechanism, typically hydraulic fluid, to apply additional pressure to the outside of the sealing element. The additional pressure on the sealing element allows the rotating BOP to be used for higher well bore pressures.
Prior art rotating BOPs have several drawbacks. One of the drawbacks is that the rotation of the drill pipe wears out the sealing element. The passage of pipe joints, down hole tools, and drill bits through the rotating BOP causes the sealing element to expand and contract repeatedly, which also causes the sealing element to become worn. When the sealing element becomes sufficiently worn, it must be replaced. Replacement of the sealing element can only occur when the drilling operations are stopped. Repeated stoppages in the drilling operations lower productivity because the well takes longer to drill. Increased longevity of the sealing element would result in fewer replacements and, thus, less down time and increased productivity. Therefore, a need exists for a rotating BOP with a sealing element having increased longevity.
U.S. Pat. No. 6,129,152 (the '152 patent) to Hosie, entitled “Rotating BOP and Method” discloses the use of bearings to allow the sealing element to rotate with the drill pipe. The bearings are subject to wear due to rotation. Thus, a need exists in the art for a rotating BOP design in which the lifetime of the bearings for the rotating sealing element is increased.
Some prior art rotating BOP's use a large number of ball bearings to reduce wear. But a rotating BOP using ball bearings requires that the rotating BOP be removed from the drilling site in order to replace the ball bearings. Thus, the prior art replacement method is time consuming and results in additional down time at the drilling site. If the rotating BOP could be “swapped out” with another unit, the reduction in downtime would mean greater productivity. Therefore, a need exists for a rotating BOP that is interchangeable and that may be engaged and disengaged rapidly.
An additional problem encountered with prior art rotating BOPs, including the '152 patent rotating BOP, is that the vertical height of the sealing element is increased to allow the sealing element to withstand higher pressures. API standards require an annular BOP to be used in the BOP stack below the rotating BOP. In extreme cases, the BOP stack can reach thirty feet in height. Drilling engineers are constantly seeking ways to decrease the height of the BOP stack. Decreasing the height of the sealing element for a given pressure rating would decrease the height of the rotating BOP, and thus decrease the height of the BOP stack. Consequently, a need exists for a sealing element that is shorter than prior art sealing elements while maintaining the same pressure differential as the prior art sealing elements.